1. Field of the Invention
The field of technology of the invention is the treatment of fluid systems wherein corrosive conditions may exist, and more specifically, the detection of primary amines or ammonia in such fluid systems.
2. Description of the Prior Art
The uses of steam include comfort heating, hot water heating, food services, humidification, sterilization, and laundry services. Direct steam injection can be used to humidify room air or to heat liquids or objects. More commonly, the steam flows through a heat exchanger and transfers energy to another fluid without making direct contact with that fluid. The term condensate refers to steam that has condensed to the liquid state (water) during the heat exchange process. Condensate is commonly collected through a system of tanks, traps, and receivers so that it can be returned to the boiler and used as feed water.
Boiler feed water typically consists of both make-up water and returned condensate. The make-up water is generally purified water from a primary source such as a city water system, a well, or a river. Make-up water replaces hydraulic losses in the boiler system such as steam that was not returned as condensate. Another major hydraulic loss is boiler blowdown or water that is released from the boiler itself. Blowdown is necessary to limit the concentration of dissolved solids in the boiler water. A primary objective in the successful operation of any steam generating system is to maximize its overall efficiency and reliability while minimizing problems related to water and steam quality. One of the greatest factors in achieving this objective is the amount and purity of condensate returned to the boiler as feed water. Returned condensate, being condensed steam, is extremely pure and has a relatively high heat content, making it ideal for boiler feed water.
As more condensate is returned, less make-up water is required, thereby saving on both water and pretreatment costs. Since condensate is already hot (typically between 180.degree. and 200.degree. F.), less fuel is required to convert it into steam. The high purity of condensate reduces the need for boiler blowdown, thereby reducing water, energy, and chemical loss. The overall scale-forming tendency of the boiler water is also reduced by condensate return and results in cleaner heat transfer surfaces.
While the use of high purity hot condensate contributes to the efficiency of steam generating equipment, the presence of very small amounts of contaminants in the liquid condensate can cause damaging corrosion of most ferrous and nonferrous metals in the condensate system, including piping and equipment. When metal oxide corrosion products formed in the condensate system are returned to the boiler they have a strong propensity to deposit on the heat transfer surfaces. This deposition limits heat transfer efficiency in the boiler and can initiate under-deposit corrosion mechanisms. Therefore, there is a strong desire to limit corrosion in boiler condensate systems.
The major causes of corrosion are dissolved gases such as carbon dioxide (CO.sub.2) and oxygen (O.sub.2). Oxygen is present due to air leakage into the condensate system components and can be excluded by good design and maintenance practices. The major source of CO.sub.2 in the steam is the thermal breakdown of bicarbonate and carbonate alkalinity present in the feed water. At boiler operational temperatures and pressures, the following alkalinity reactions occur: EQU 2 NaHCO.sub.3 .fwdarw.Na.sub.2 CO.sub.3 +CO.sub.2 +H.sub.2 O (Equation 1) EQU Na.sub.2 CO.sub.3 +H.sub.2 O.revreaction.2 NaOH+CO.sub.2 (Equation 2)
The breakdown of the bicarbonates (see Equation 1) proceeds to 100% completion. Carbonate breakdown (see Equation 2) proceeds from about 70 to about 100% completion, depending on the boiler pressure. The CO.sub.2 liberated in both reactions is carried with the steam and dissolves in the condensate. As it dissolves, it forms carbonic acid: EQU CO.sub.2 +H.sub.2 O.revreaction.H.sub.2 CO.sub.3 .revreaction.H.sup.+ +HCO.sub.3.sup.- (Equation 3)
Since condensate is extremely pure, even small quantities of carbonic acid can significantly lower condensate pH and correspondingly increase its corrosivity. As little as 1 ppm of CO.sub.2 in the steam can depress the pH of the condensate to 5.5. High alkalinity feed water will produce very corrosive condensate.
The corrosion reaction of carbonic acid with iron produces ferrous bicarbonate, Fe(HCO.sub.3).sub.2, and hydrogen gas: EQU Fe+2H.sup.+ +2 HCO.sub.3.sup.-2 .fwdarw.Fe(HCO.sub.3).sub.2 +H.sub.2 (Equation 4)
The soluble ferrous bicarbonate is carried away with the condensate, leaving behind an area of obvious metal loss. The corrosion usually appears as a uniform attack leaving a rather smooth surface where the iron has dissolved away.
Corrosion of a condensate system can be inhibited by either mechanical or chemical means, although neither is completely effective when used alone. Nearly all modern boiler systems are protected by a combination of the two. Mechanical elimination of all avenues of air and process fluid in-leakage is an essential part of system protection. Feed water oxygen can be completely eliminated by mechanical deaeration plus the use of a chemical oxygen scavenger. In addition, various pretreatment processes such as hot lime softening, dealkylization, or demineralization can be used to reduce or eliminate make-up water bicarbonates and carbonates. However, even with pretreatment to reduce potential CO.sub.2, chemical inhibitors are usually necessary for complete protection.
Three basic types of chemical corrosion inhibitors are used for condensate corrosion control: neutralizing amines, filming amines, and oxygen scavengers/metal passivators.
Neutralizing amines are typically volatile, alkaline compounds that are added to either the boiler feed water or the steam supply systems. They function by volatilizing into the steam and re-dissolving in the condensate with the CO.sub.2. The amines chemically neutralize any acid present in the system. They raise pH to a level at which the condensate is much less aggressive towards the metallic components of the system.
Most commercially available neutralizing amine condensate treatments are blends of various amines. The blends offer combinations of certain characteristics that are unique to each amine. The characteristics of greatest importance when selecting amines are volatility, acid neutralizing ability, and basicity. Every volatile substance in a boiler system, or similar type system, has a specific volatility or vapor to liquid distribution ratio. The distribution ratio is defined by: EQU V/L=Concentration in the Vapor or Steam Phase/Concentration in the Liquid or Condensate Phase
The distribution ratio indicates the portion of a given amine that will condense with the condensate or stay with the steam in a given piece of equipment. To neutralize CO.sub.2, the amine must be in the condensate as the CO.sub.2 dissolves.
Another very important criterion for amine choice is acid neutralizing ability. This is the amount of amine required on a weight basis to neutralize the carbonic acid present. The amine reacts with the carbonic acid in solution to form an amine bicarbonate: EQU RNH.sub.2 +H.sup.+ +HCO.sub.3.sup.- .fwdarw.RNH.sub.3.sup.+ +HCO.sub.3.sup.-(Equation 5)
Although Equation 5 is for a primary amine, secondary and tertiary amines are also used for condensate treatment.
Once all of the acid in the condensate system has been neutralized (at a pH of about 8.3), amine basicity becomes important. Any additional amine added to the condensate system will hydrolyze, raising the condensate pH: EQU RNH.sub.2 +H.sub.2 O.fwdarw.RNH.sub.3.sup.+ +OH.sup.- (Equation 6)
Basicities of neutralizing amines also vary. Above a certain pH, additional quantities of the weaker neutralizing amines do little to further increase the pH.
Neutralizing amine programs are most effective when fed to maintain a condensate pH of from about 8.5 to about 9.5, a range of maximum corrosion protection for both ferrous and copper alloys. Because the amines are added to the system in direct proportion to the amount of CO.sub.2 in the steam, high alkalinity feed water requires considerable amounts of amine to obtain the desired pi range. The cost of such a program may be prohibitive and alternative means of corrosion protection may be desired.
Filming amines are high molecular weight amines with long-chain hydrocarbon alkyl groups. The amine-containing end of the molecule chemisorbs to the metal surfaces of the condensate system while the hydrophobic tail of the molecule extends away from the metal surface. A monomolecular, non-wettable film is thereby created on all metal surfaces that come into contact with condensate containing the filming amine. This film acts as a physical barrier between metal surfaces and corrosive condensate, offering protection against CO.sub.2. Unlike neutralizing programs, filming amines protect the condensate system from O.sub.2 attack. Since filming amines react with the metal surface instead of with a dissolved corrosive species, their feed rates are not directly proportional to the amount of contaminate (such as O.sub.2 and CO.sub.2) in the steam. Instead, the amount of filming amine required is related to the system's surface area.
The protective amine film is generally quite stable, but extreme pH conditions (high or low) may cause it to strip off the metal surfaces. Filming amines must be fed continuously to ensure that no gaps in protection occur in any parts of the system. However, excessive feed may cause the filming amine to accumulate as sticky masses in receivers, traps, valves, or any collection point. Therefore, periodic field testing is required to maintain a specified amount of filming amine in the condensate to avoid such deposits.
An alternative to filming amines for dissolved oxygen corrosion inhibition in condensate systems is the use of volatile oxygen scavengers in combination with neutralizing amines. The scavenger reacts directly with any oxygen present while the neutralizer provides protection from CO.sub.2 corrosion. Such programs are controlled by the same parameters as neutralizing amine programs.
Examples of amines that are commonly added to boiler water systems include: diethylaminoethanol; morpholine; methoxypropyl amine; cyclohexyl amine; monoethanol amine; methyl amine; ethyl amine; propyl amine; butyl amine; t-butyl amine; octadecyl amine; and, mixtures of these amines.